Commonly, heavy oils and bitumen are difficult to transport from their production areas due to their high viscosities at typical handling temperatures. Regardless of the recovery method used for their extraction including costly thermal enhanced oil recovery methods, heavy oils and bitumen generally need to be diluted by blending the oil with low density and low viscosity solvents, typically gas condensate, naphtha and/or lighter oil to make the heavy oils and bitumen transportable over long distances.
As a result, various methods are typically used to make heavy hydrocarbon mixtures transportable. Importantly, as viscosity is the key fluid property to make a heavy hydrocarbon mixture transportable increasing temperature causes significant reductions in the viscosity of heavy hydrocarbons as shown in FIG. 1b. As is well known, light oils generally have much lower viscosity values and therefore flow easier through pipelines. As an example, the variation of viscosity of a heavy hydrocarbon mixture with the content of a naphtha diluent is shown in FIG. 1a. 
Consequentially, there are typically two physical methods that may be used for reducing viscosity to assist in the transportation of heavy hydrocarbons. The first is the application of heat to the hydrocarbons, which reduces their viscosity to such an extent that the mixture can flow through pipelines. As the oil flows in the pipelines, the oil loses heat, and thus, it needs to be constantly warmed. This method is unpractical and very expensive if the heavy hydrocarbon mixture is to travel long distances. The second physical method is dilution, which is the preferred physical method for transporting heavy hydrocarbons over long distances. The disadvantages of dilution are, first, that remoteness makes the construction of pipelines for sending or returning the diluents to the heavy hydrocarbon production zone considerably expensive. The second disadvantage is that the availability of diluents, typically light hydrocarbons, is steadily decreasing since these diluents are fuels by themselves and the reserves of light hydrocarbons are generally being reduced worldwide.
Chemical processing has become more an attractive alternative for making heavy hydrocarbons transportable, and in some cases chemical processing is the only viable alternative to carry heavy hydrocarbon mixtures to refineries and market places. Most chemical processes for making heavy hydrocarbon mixtures transportable are thermal cracking systems. Either moderate cracking such as visbreaking or more severe processes such as coking systems have being proposed. These processes are generally applied to the heaviest hydrocarbons in the heavy hydrocarbon mixture, namely the fraction called the vacuum residue. Both processes reduce the stability of the hydrocarbon mixture due to the increase of the heaviest hydrocarbons called asphaltenes during processing and their tendency to precipitate.
For example, visbreaking is a moderate thermal cracking setup that works at low pressure (−60-120 psi) and relatively moderate temperature (430-480° C.) and reduces the viscosity of heavy hydrocarbon mixtures. The extent or severity of visbreaking is limited by the stability of the asphaltenes.
Other thermal processes generally pose disposal problems due to the relative severity of processing which results in the production of solid hydrocarbons as a byproduct. These thermal processes are generally called coking processes. The fact that these processes produce coke out of about 20-30% weight of the oil produced in the fields limits their applicability due to increased costs and most noticeably, to the environmental impact such quantities of a solid by-product rich in metals and sulfur would cause in remote areas where many of the heavy hydrocarbon reservoirs are located.
Other known chemical processes use catalysts and are also applied to the residual hydrocarbons. For example hydro-processing requires using hydrogen and typically high pressures. Steam catalytic processing of the heaviest hydrocarbons, as described in U.S. Pat. Nos. 5,688,395, 5,688,741, 5,885,441 and Canadian Patent No.'s 2204836 and 2233699, that improve the performance of thermal cracking or visbreaking may make the processed heavy hydrocarbon mixture transportable in terms of viscosity. Nevertheless, steam cracking processes are still limited by the stability of cracked asphaltenes which make the processed heavy hydrocarbon mixtures unstable, jeopardizing the mixtures compatibility with other hydrocarbon streams if sent through pipelines. Similarly to visbreaking, the transportable heavy hydrocarbon mixture from steam cracking of residual hydrocarbons yields poor quality light fractions in refineries and can cause significant fouling in pipelines and vessels during refining, precisely because the heaviest molecules remaining have already been processed.
Dilution is a transportation practice generally unsustainable in the mid/short term due to several reasons, the most noticeable being:                a. Naphtha deficiency is increasing in the zones where many heavy oil production fields are located and in remote zones where new discoveries of these oils are occurring.        b. Availability of light oils for use as diluents is decreasing, paralleling the worldwide trend of conventional oils reserves. Only the high prices of oil provide incentive to transport light oils by blending them with lower quality heavy oils, which helps the latter to get to the markets.        c. The construction and maintenance of long distance diluent pipelines for transporting gas condensate, naphtha or light crude oils is expensive, and is an environmental risk given the flammability of these light hydrocarbons. Any minor leak may lead to explosion and fires with the potential of destroying wildlife and resources. The remoteness of the Heavy oils reservoirs leads to difficult immediate responses to prevent major damages to the environment due to oil ducts leaking. For these and other reasons, high socio-political resistance from remote communities is nowadays generally found wherever oil pipelines are proposed for construction.        d. Heavy oils typically present a high acidity level, which is one of their undesired features along with their poor virgin yields of light fractions in the range of transportation fuels. Acidity is caused by the presence in these oils of naphthenic acids, which are hydrocarbons containing chemical functionalities that involve carboxyl and sulfide compounds able to release extremely labile protons at moderate temperatures. This ability promotes corrosion once in contact with metallic walls such as those of pipelines and at processing, upgrading and/or refinery units. Acidity in heavy oils is not destroyed by dilution. At present, no effective low temperature chemistry to neutralize heavy oils acidity has been found that doesn't generate additional or insurmountable difficulties. Acidity is relatively easy to destroy under conventional upgrading processing, where hydrotreating or hydrocracking of vacuum gas oils takes place and/or hydro or thermal processing of the residues occurs.        e. In heavy oils-diluent blends, stability may be an issue in some cases, specifically for heavy oils that contain a significant proportion of asphaltenes, which is the fraction of heavy hydrocarbons that precipitates in the presence of light paraffins. If the diluent (gas condensates, naphtha or light oil) is rich in light paraffins and the heavy oil is rich in asphaltenes or is predominantly constituted of highly aromatic asphaltenes, the heavy oil-diluent blend will be prone to precipitate whenever a slight variation in solubility occurs, either in pipelines or storage tanks or both. Remarkably, light crude oil asphaltenes are typically less stable than the ones in heavy oils, thus they may tend to first precipitate over those in heavy oils when blends of light and heavy crude oils are produced for transporting the latter.        
In remote zones where scarcity of diluents for large heavy oil reservoir developments already exists, the construction of upgraders in the nearby area has generally been found to be a good solution both technically and economically. The upgraders in Northern Alberta, Canada are one example of extended heavy oils reserves where there is a lack of light oils available in the vicinity. Enormous costs have been incurred to produce upgrading in the Northern Alberta area to date and there is still a need for different technological solutions to reduce the costs of new upgraders to develop the vast majority of the still unexploited reserves of bitumen located in this remote area. Similar constraints exist for the extra heavy oil present in the Orinoco basin in Venezuela, and other heavy oil reservoirs throughout the world
In many other locations worldwide where medium/small heavy oil reservoirs are being exploited, generally no viable technological and economical solution has been developed to overcome the problems of dilution. The up-scaling benefits of conventional upgraders cannot be captured since many reservoirs are not rich enough to justify investments in upgraders, even though the reservoirs may be very economically attractive for exploitation. Additionally, many of these reservoirs are placed in difficult, far away geographies, and at times are located within environmentally protected areas where large developments beyond certain limits and/or release/accumulation of significant quantities of waste are intolerable.
Field Upgrading: Transcending Dilution Limitations
Most upgrading technologies commercially offered or installed are adaptations from refinery environments with a few modifications to fit them into facilities and service restrictive environments. These upgraders, very much like in the current most efficient deep conversion refineries, transform the vacuum residual fraction, the one that remains undistilled under a vacuum at atmospheric equivalent temperatures typically higher than 560° C. or even lower. Residue constitutes usually higher than 30 wt % of the heavy oil, typically higher than 50% in extra heavy oil and bitumen such as the ones in Northern Alberta, Canada, or in Northern Orinoco area in Venezuela. But unlike upgraders, refineries for which the current residue upgrading processes were developed are mostly placed in industrialized areas with abundant utilities and services. Refineries have a wide variety of transporting options and access to disposition alternatives; upgraders usually do not have all these advantages.
Typically, transportable oil requires a minimum API gravity and viscosity. For example, in Canada, commercial pipelines require a minimum 19° API and 350 centistokes at the pipeline reference temperature. Other regions will have other requirements which take into account location as well as climate/seasonal conditions
The situation of most of the newest and undeveloped heavy oil fields imposes rethinking heavy oils upgrading in such a way that transportable oil can be reached with energetic and environmental efficiency and relative low complexity yet low investment costs.
Thus, solutions are needed for all cases mentioned above in which there is no (or there is limited) economic viability for conventional scale upgrading, and/or in which a minimization of the environmental impact of the upgrading activity is required, and for cases where limited or no availability of diluent exist, which are becoming more and more common.
A review of the prior art reveals that U.S. Pat. Nos. 5,688,395, 5,688,741 and 5,885,441 published a residual processing that uses a chemistry valuable for moderated heavy oils upgrading (Thermo-Catalytic Steam Cracking). These processes use low-pressure steam dissociation applicable to alkyl aromatics present in the residual fraction. This technology reduces the residual fraction, while producing light hydrocarbon fractions to result in a moderate upgrading in the range of 14-15° API from the typical 8-10° API originally in the bitumen or extra heavy oil of the examples shown in these patents. The same chemistry is applicable to distillable gasoil fractions existing in heavy oils, as established in U.S. Pat. No. 6,030,522. In this technology, the process claimed is inserted upstream of a fluid catalytic cracking (FCC) unit, in a configuration typical of a conversion refinery.
In the technologies of the prior art discussed above, with residual processing, the improvement obtained is achieved at the expense of deteriorating the stability of the post-processed oil. In fact it is generally the stability of asphaltenes in the converted residual that limit the performance of the process. As the conversion of the residual arrives at levels higher than 35 wt % for some residuals, or higher than 40 wt % in other crude oils, the stability of asphaltenes approaches tolerance limits established for transportation of heavy fuels and residual fuels. P-value is one of many stability scales used as indicative of the stability of the residual fuel or heavy oil. It establishes that when processed oil reaches a P-value of 1, it is unstable; a safe P-value limit is usually set between 1.15 and 1.25. For virgin heavy oils, P-values are usually around 2.5-2.8 or even higher. For virgin light oils P-values are lower, below 2 in many cases, with virgin Arabian light crude oils presenting values around 1.7. A low P-value in an unprocessed oil means that the residue can only be moderately thermally cracked to produce a low conversion of the residual before the instability onset is reached (P-value lower than 1.15).
Asphaltene stability loss during cracking of residuals considerably affects the options of many technologies for field upgrading of heavy oils exploited from remote reservoirs of heavy oils. For instance, thermo-catalytic steam cracking (CSC) of residuals requires the process to be used at its highest severity limits to meet transporting requirements. Even if a heavy oil were recessed by catalytic steam cracking to reach 14-15° API under the scheme of the U.S. Pat. No. 5,885,441 and the required transporting viscosity (typically lower than 350 cP), these oils would have been processed at the stability limit. Crude oil close to instability is affected in pipeline transportability due to the high potential of sediment formation within the pipelines and to blending limitations since any contact with paraffinic oil could induce precipitation of asphaltenes. Furthermore, as the field-upgraded oil produced would need to go to refineries, additional problems of stability would result in these facilities that could limit the uptake of such oil at the refinery site, as for example excessive fouling in heat exchangers and furnace coils and solid deposits inside distillation columns.